All posts by bravr

Offshore Drillers Begin to Emerge from Stormy Seas

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After almost three years of dwindling demand, offshore drillers are seeing the first signs of a turnaround. Global offshore rig count appears near bottom after falling over 40% from its cyclical peak. And bidding for future work is accelerating as both drillers and operators recalibrate to make projects work at lower commodity prices.

Not all of the emerging work will carry high day-rates. In the short term, well interventions, sidetracks, and plug and abandonments will represent more demand than usual. Longer term, more lucrative drilling will be driven by still-materializing cost reductions, including savings from standardization and preventative maintenance improvements.

Even a modest upturn will be welcome, however. After OPEC’s decision to open the spigots in 2014, drillers scrambled to adjust to the abrupt change in market conditions. News of reorganizations, asset sales, fleet reductions, rig-delivery delays, and recapitalizations came to dominate the sector. On average, share prices of the largest providers fell a staggering 79% over the period.

The segment still faces some headwinds. Day rates will remain under pressure at least through 2017. And offshore discoveries—the lifeblood of future drilling—are down almost 60% from 2014 levels. As a result, new reserves totaled only 2.4 billion barrels last year.

While these factors augur well for oil prices longer term, they point to more tepid demand growth in the mean time. For the projects that do materialize, new rigs coming out of shipyards will ensure that competition remains stiff.

Still, some contractors will benefit more than others as offshore work increases. The following metrics and resulting scoreboard can help determine which are best positioned:

Stock-price Performance: The ability of a driller to operate
effectively during times of change is important. Stock-price
performance since Q2 2014 is a proxy for how companies handled the
steep decline in oil prices.
Return on Assets: ROA measures the effectiveness of a company’s
management, strategy and operations. While ROA can vary based on how
aggressively a driller retires or writes down assets, it’s worth
watching.
Debt-to-Equity Ratio: A high debt-to-equity (D/E) ratio limits
flexibility. Moreover, management teams focused on servicing debt are
less focused on other aspects of the business.
Backlog Ratio: This measures backlog relative to the book value of a
driller’s fixed assets (mostly rigs). A higher ratio connotes greater
visibility to the business. The ratio is a financial proxy for
customer preference and faith in a driller.
Customer Satisfaction: EnergyPoint Research’s independent customer
satisfaction scores can be strong indicators of future financial
performance. The reasons are self-evident: customers contract with
their preferred drillers more often, for longer periods and at higher
rates.
Customer Satisfaction Trends: Market changes affect performance. This
metric captures driller trends in customer satisfaction since oil
prices began weakening in Q2 2014.

The scoreboard’s “INDEX” is the average of driller rankings across the six metrics—with customer satisfaction metrics receiving double weighting.

Note – Ranking are shown in parentheses.

The results suggest Ensco and Noble are currently the best positioned for an upturn. Transocean, Diamond Offshore and Rowan follow.

Ensco and Noble outperform in customer satisfaction, while Transocean and Diamond benefit from strong backlogs. Leading ROA and stock-price performance, as well as balance-sheet strength, drive Rowan’s standing.

Atwood Oceanics’ scorecard is burdened by its customer satisfaction trend and lower ROA. However, the company retains low leverage and the resources to rebound. The metrics for Seadrill reflect a company in distress with rankings in the bottom half of each dimension.

So, why does the INDEX overweight customer satisfaction? Because when customer satisfaction moves in a particular direction, operational and financial performance tend to follow.

As a general rule, customer perceptions of a driller’s job quality, performance and reliability, and service and professionalism go a long way toward predicting overall customer satisfaction. Although drillers as a group have done a relatively good job in these areas, there is room for improvement for individual drillers.

Below is a summary of these key customer satisfaction dimensions and why they matter:

Job Quality: A measure of a contractor’s organizational and
procedural effectiveness. Job quality influences overall satisfaction
because is reflects whether contractors meet expectations.
Performance & Reliability: Performance and reliability measures the
dependability of personnel and assets. Contractors that proactively
address shortfalls enjoy higher customer loyalty.
Service & Professionalism: Highly rated contractors tend to be
selective in their hiring and have higher rates of employee
retention. A drive to maintain long-term customer relationships is
pervasive at all levels.

Few can say precisely what the future holds for offshore drillers. However, with conditions gradually improving, it’s a good bet drillers mastering the things that matter to customers will see their opportunities grow and financial results outperform.

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PDVSA Continues to Demonstrate Deterioration on all Fronts

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By Pietro Donatello Pitts (@PietroDPitts), Special to Energy Analytics Institute (EAI)

In recent weeks PDVSA has reported at least three accidents: Petrotrin oil spill in Sucre state and incidents at its Cardon and Curaçao refineries. The writing on the wall continues to point to a cash-strapped state oil company with an inability to make investments, retain top talent, organically grow oil production, and let alone take on the leadership role in Venezuela’s upstream, downstream, or midstream sectors.

Recent events at PDVSA’s Cardon and Curaçao refineries demonstrate conditions at the company’s refineries continue to deteriorate as I would expect due to a lack of investments, upgrades and maintenance and as chronicled in an earlier article I wrote titled “Mange Infested Dog Roams Grounds of PDVSA’s Paraguana Refining Complex” http://bit.ly/2q9yySx

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Unconventional Plays – Is there an optimal number of fractures to maximize well profitability?

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We frequently hear that unconventional plays require massive amounts of stimulation to unleash hydrocarbon reserves, but how do we know if the number of fractures will result in the most profitable well design? Targeting the highest initial flow rate may not lead to the best economic outcome of a well development plan.

Recent developments in fracking technology have enabled year-over-year increases in fracking density for unconventional fields, and as a result we find that recently completed wells in unconventional plays show higher fracking density per well than older wells. This is the basic premise for the analysis that follows.

We can analyze how fracture density impacts the fluid recovery volume per well by examining Enno Peters’ excellent work published by OilPro in January and February 2017.

In the Niobrara Play (Fig. 1), we observe a tendency of higher oil recovery per well for recently completed wells with higher fracture density.

However, in the North Dakota, despite the higher initial flow rates from recently completed wells and the larger number of fractures, we can’t clearly observe a similar tendency.

These results suggest that reservoir and fluid conditions play an important role in defining the best fracture density in horizontal wells.
Today, a numerical well design software is available to simulate near wellbore coupling between reservoir and well completion architectures. With its use, we can accurately predict the performance of a specific well placed within a defined reservoir based on fluid conditions, number of fractures, gravel packs, and other characteristics. The use of numerical simulators can significantly reduce well development costs by eliminating the need to physically build several test wells before selecting the most profitable completion well design for the development plan.

Figure 3 below shows a 5-year production curve from a commercial well design simulator with the following theoretical reservoir and fluid parameters: Kh= 0.005 mD, Kv= 0.0015 mD, fluid= oil, viscosity=0.1 cp, Reservoir thickness= 150 ft, total compressibility= 1.5×10-5, a fixed downhole flow pressure, with a 7500 ft horizontal section inside a drainage area of 1200 ft x 9000 ft, and simulating several fracture densities.

The results show a large difference in produced volumes during the first 2 years when comparing wells with different fracture densities. However, the large differences decline rapidly over time until they become small by year 5. Despite the initial differences the overall production estimates for this well are not significantly impacted by the choice in fracking density.
Given these results, what is the optimal fracking density to maximize the well’s profitability? The most cost-effective completion choice can be identified by looking at the well’s cash flow estimates and the initial fracking cost based on fracture density.

Figure 4 shows similar production curves as the previous example, except for the reservoir permeability, which was reduced to: Kh= 0.0005 mD, Kv= 0.00015 mD.

These results show large differences in produced volumes throughout the period. In this case, it is clear that higher fracture density would significantly impact the well’s oil recovery volumes. Again, the most cost-effective completion alternative can be identified by the cash flow estimates and initial cost for each fracture density choice.
In unconventional field development, there is no “one solution for all cases”, or “the more fractures the better”, because a higher fracking density or the longer horizontal well does not necessarily result in the most profitable well.

Today, it is possible to identify a solution fit for each specific permeability, fluid viscosity, reservoir thickness, and other parameters, that would result in the most profitable well completion architecture to be used. This optimization process will help push the breakeven production cost of oil down, and promote sustainable activity for unconventional plays.

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Oil Price Commentary: A Positive Week Ahead for Oil Price

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Last Week Oil Market Data:

Crude Oil Price Movement: Oil prices moved higher last week on support from OPEC production cut extension, decline in U.S. crude oil production and draw-down in U.S. crude oil and gasoline stockpiles. Brent crude and WTI closed the week up by more than 5 percent to around $53.80/bbl and $50.85/bbl respectively.

U.S. Crude Oil Inventories: U.S. crude inventories decreased by 1.8 million bbl to the week ending May 12. Last week’s draw-down in US crude inventories followed another week of a significant fall in stockpiles. The fall in stockpiles supported oil prices to edge higher on Wednesday.

U.S. Gasoline Stocks: U.S. gasoline inventories fell by 0.4 million bbl to the week ending May 12. U.S. gasoline inventories have been falling for for almost two weeks now following few weeks of build-up. A trend that is supporting the upward movement in oil prices along with other market parameters.

Weekly U.S. Crude Oil Production: Last week, U.S. crude oil production fell for the first time following few months of continuous increase. Last week, U.S. crude oil production decreased by 9,000 bbl/day to 9,305,000 bbl/day. At its current level, US crude oil production is up by more than 514,000 bbl/day from the same time a year ago. The fall in U.S. crude oil production has supported oil prices last week and it is expected to positively support the upward movement in oil prices this week as well. Despite last week decline in US crude oil production, it is still expected that U.S. crude output will continue to increase and the increase could accelerate after OPEC meeting.

U.S. Rig Count: U.S rig count increased by 16 rigs to 901. Oil rig count was up by 8 rigs to 720, while gas rig count was up by 8 rig to 180 as well. At its current level, U.S. rig count is up by 497 rigs from the same time a year ago. With the recent announcement from two of the biggest OPEC and non-OPEC producers to extend the oil output cut, it is expected that U.S. rig count will continue its growth.

This Week Oil Price Forecast:

Last week oil market data and news were quite positive. Starting with the drawdown in U.S. crude oil and gasoline inventories following a significant drawdown the week before, decline in U.S. crude oil production, weakening U.S. dollar aimed Trump’s political woes, and finally the assurance from Saudi Arabia that OPEC and other oil producers are on course to agree an extension of supply cuts during their meeting on May 23. All these positive sentiments have driven oil prices last week by more than 5 percent and are expected to drive oil prices up this week as well.

Looking at last week oil market data and news, and this week’s expected events, it is obvious that oil prices is set for a positive week ahead. Oil price is expected to continue trading on the green this week and could hit levels not seen since February 2017. Brent crude and WTI are expected to continue their upward movement and could go up by 1 to 2 percent in the first two days of trading. On Thursday, which is the day when OPEC’s 172nd ordinary meeting is due to take place in Vienna, Austria, oil prices could go up by 3 percent.

We expect U.S. crude oil production and rig count data for this week to show increase in both oil output and rig count, however, these data will not have a significant impact on oil prices as the oil market, traders and investors are focused on OPEC’s meeting.

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Oil up on expectations of extended, possibly deeper, output cut

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Oil prices rose on Monday, bolstered by confidence that top exporters will this week agree to extend supply curbs, with suggestions the cuts could even be deepened.

Prices have risen on expectations that the Organization of the Petroleum Exporting Countries (OPEC) and other producers, including Russia, will extend for another six or nine months a deal to cut supplies by 1.8 million barrels per day (bpd).

Some analysts argue that deeper cuts are required to balance the market, pointing to a slight rise in OPEC exports this year.

Full Article: Reuters

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How to Battle Fractivists in One Easy Lesson

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The oil and gas industry has always been focused on production and is rather poor at fighting, but Texans for Natural Gas shows how to battle fractivists.

The oil and gas industry is notoriously bad (pipeline companies being the worst) and very slow, by tradition, in doing politics. Likewise, most landowners who want the industry in their backyard are just too polite to do battle. Both the industry and its natural constituencies are driven by motives of being businesslike, friendly and unfailingly positive.

Unfortunately, that’s not enough in today’s world and probably never was if we consider some the earliest political campaigns of our nation. Successful politicians know the public always says it hates negative campaigning, yet unfailingly responds to it. There are limits, of course, and one hopes we don’t get back to where one refers to the other as a “mean-spirited, low-lived fellow, the son of a half-breed,” as Adams did of Jefferson.

Read more:

http://naturalgasnow.org/battle-fractivists-one-easy-lesson/

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ENI begins production of oil

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Production of oil from the country’s third independent oil and gas field, operated by Italian oil giant, Ente Nazionale Idrocarburi (ENI), began from the Offshore Cape Three Points (OCTP) in the Western Region yesterday.

Production began after the company successfully installed all the subsea infrastructure and hooked it onto the production platform FPSO John Agyekum Kufuor, which arrived in the country on April 10, this year and was anchored to the OCTP Field in the Tano Basin.

He said the feat was also a testimony of the exploration skills and knowledge, as well as the field development vision of ENI and its partners, adding that “it confirms the effectiveness of our new operational model, where ENI has a central role in project management, aimed at improving time-to-market”.

The takeoff of OCTP project is expected to provide gas for the country’s energy sector for more than 15 years for electricity generation to boost the country’s growth and transformation agenda.

Full Article: Graphic Online

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Oil price, Pantheon, And finally…

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WTI $50.33 +98c, Brent $53.61 +$1.10, Diff -$3.28 +12c, NG $3.26 +7c
Oil price
With the Opec and Non-Opec meetings due this week, culminating on Thursday with what should be a straightforward  discussion about whether to extend by 6 or 9 months the only change appears to be around deepening the cuts. I suspect that anything of that order will be discussed but probably kept back for a rainy day, it may be that should there be less than hoped for draw of stocks a bigger cut will be needed. Elsewhere the rig count on Fridayshowed a rise of 16 units overall, oil was up 8 at 720. Finally I’m sure that you dont need reminding that next Monday is Memorial Day in the US which signals the start of the driving season, let battle commence…
Pantheon Resources
A long-awaited operational update from PANR on Friday which gave some clarity about the problems that they had encountered at both the VOBM#4 well and the VOBM#2H wells and details of a gas processing plant to be constructed. In a conference call this morning the CEO, Jay Cheatham, answered a few pre-prepared questions about the situation. The first thing to realise is that the problems on both wells were wellbore specific and in some cases it appears to me that they had some pretty rank service company attention.
In the VOBM#4 well it appears that finding the Wilcox gas which was never even on the agenda may prove to be quite a winner. After failure of the liner hanger to seal correctly it seems that the best thing to do is to drill a sidetrack and produce the Wilcox leaving the opportunity to drill another well from the same position to go after the Eagleford sandstone.
The VOBM#2H caused problems after the attempt to re-enter the suspended horizontal wellbore and drill  a deviated well path caused technical challenges. It seems now that that well will be best completed as an upper tier well and that fraccing it will provide good flow rates, and that as it lies between the 1 and the 3 well,  will provide ‘significant potential’.
As a result of this news PANR has announced an agreement with Kinder Morgan to construct a 15 mmcf/d gas processing plant to receive the offtake from these three wells. This amount of gas would generate over $1.6m per month of free cash flow to the company. There is no doubt that this is not huge but CEO Cheatham said on the call that it was ‘a compromise with room to grow’.
Pantheon has $4.7m of cash and total commitments until the expected cash inflow in say, October are considerably less than that, giving the company adequate scope for further operations. The recent operational problems cannot be forgotten but they havent changed the resource number which is substantial and the timescale is still attractive. Finally this company is fully intending to drill out sufficient wells to prove up its acreage and then sell on, investors have a rare opportunity to participate in this journey. I havent changed my 200p target price through thick and thin, I will leave it like that for the time being…
Sundry
Premier has spudded its Zama-1 well offshore Mexico which I am told its in-house team are very excited about. Indeed my last comments about being high-risk high-reward went down badly as it is relatively low-risk but with the potential of 100-150m barrels!
Echo Energy confirmed that Pegasus A Fund is investing £10m in the business and will be at no discount as suggested. Echo is building up nicely now and I imagine that investments in South America are very likely to be seen before long.
Wood Group has won a contract with Sakhalin Energy for engineering support services for Sakhalin-2, no amount given but a long contract and likely pretty important.
Finally, Providence Resources has announced that FEL 3/04 has been extended until 2019, this is the famous Dunquin block where currently work is ongoing to try and ‘square the circle’.
And finally…
A huge weekend of sport, in the end the Noisy Neighbours and the HubCap Stealers joined Chelski and Spurs in the Champions League spots. (Apologies for not mentioning Spurs 1-6 demolition of the Foxes the other night…)
Billy Vunipola is out of the Lions tour which is the worst news possible..But what incredible rugby at the weekend as both semis went down to the wire with the Chiefs scoring in the corner to beat Sarries 18-16 and Wasps doing the same to beat the Tigers 21-20…
In the most exciting finish of the year so far Yamaha team mates Maverick Vinales forced ‘The Doctor’, Valentino Rossi, into a rare mistake, and with 2 corners to go to the chequered flag, Rossi crashed out of a certain 2nd place, losing 20 points and his lead in the World Championship to Vinales. To the delight of the partisan crowd, this put Frenchman, Johann Zarco into 2nd place after leading the first half of the race. The final podium went to Danny Pedrosa, sparing Honda’s blushes after No 1 rider, Marc Marquez crashed out. Brit Cal Crutchlow maintained his strong finishes with 5th place. With the next race at Mugello, Rossi’s ‘home’ race, the honeymoon might be over for the Yamaha pairing ….Roll on Italy ! The Moto2 race saw Franco Morbidelli win from Bagnaia and Thomas Luthi. In Moto3 leaking oil caused a huge crash on lap 2 causing a Red Flag. In the restart Joan Mir continued his domination of this class with another win. British Team Talent rider John McPhee fought through to finish 12th. Britain’s Danny Kent, 2015 World Champion, who walked out of Moto2 last week, came in 10th on a KTM, probably ensuring himself a ride for the rest of the season.
I am taking a few days holiday, but technology permitting I hope to blog with any big news and will be at a sporting event to report back from at the weekend….
 

For more information, visit my blog: Malcy’s Blog
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Decline Curve Analysis of Shale Oil Production – Eagle Ford / Niobrara

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Decline Curve Analysis of Shale Oil Production

Uppsala University, Master Thesis in Energy Systems Engineering, Linnea Lund The Case of Eagle Ford

**> An excellent well written, detailed, and concise Thesis that is

applicable to Shale Oil Production Decline Analysis.**

Not to be confused with shale oil is oil shale. Oil shale is shale rich in kerogen which is the solid pre-stage of crude oil and natural gas (International Energy Agency, 2013), and is sometimes also called kerogen shale. Liquid hydrocarbons can be extracted from the oil shale if it is heated at a controlled rate. The petroleum in the oil shale is of less quality than the shale oil, which is high quality light oil. Other resources classified as unconventional by the IEA are coal-to-liquids and gas-to-liquids.

When estimating future production (or ultimate recover) in an oil field or an oil well the concept of decline rate is fundamental. The decline rate is the reduction in production-rate from an individual field or a group of fields, after the production has peaked (Höök et al., 2014). The decline rate is defined in Equation:
Decline Rate n = ((Production n – Production n-1) / Production n-1)
where n is usually month or year, to calculate monthly or annual decline.
Also discussed are the Arps’ decline curves – “exponential” “hyperbolic” “harmonic”.

**

Of further interest is the Niobrara / Codell Decline Curves – Denver
Basin Colorado

**

Another great fact sheet is the brief article showing various decline curves for the Niobrara in the Denver Basin. The Codell will decline in a similar fashion. Companies contributing decline curves are; Noble Energy, Anadarko, PDC, Carrizo Oil and Gas, Bill Barrett Corporation, Whiting Petroleum, and Bonanza Creek Energy.

Decline curves for almost all of the US Shale Oil and Gas plays are basically similar.

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Tsunamis behave as shallow-water waves

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Tsunami statistics make grim reading, which is why I am not going to quote any. There are some great documentaries and websites that will regale you with all the stats you need. There’s even a couple of movies, where, if you sift through the hype, you may see a smidgen of science, or hear a bit of terminology added to the dialogue to give the impression of knowledgeable heroes.

The word Tsunami derives from two Japanese words; Tsu meaning harbour, and nami wave; an appropriate etymology given that these forces of nature really come into their own along shallow coasts and harbours. About 80% of tsunamis are generated by powerful earthquakes (particularly those beneath the sea floor); the remaining 20% result from large landslides, volcanic eruptions, and less frequently (fortunately) meteorite impacts. They are sometimes referred to, incorrectly, as tidal waves. Tides result from astronomical forces. We can think of the succession of high and low tides as the passing of a wave that has a period of about 12 hours (the time from one high tide to the next). Tidal waves move along coasts such that a high tide at one location (i.e. the crest of the wave) will occur at a different time to that at a more distant location. Tides also move water masses; waves do not.

Sea and lake surface waves are generated by wind. The wind provides the energy which is transferred to surface waters. As a general rule, the stronger the wind, the greater are wave amplitude, wavelength, and speed. Water particles beneath waves have a circular or elliptical motion (referred to as orbitals); the larger circles occurring immediately below the crest, and decreasing in size to a depth that equates to about half the wavelength. This means that in deep water, waves do not interact with the sea floor. This kind of surface wave is given the name deep-water wave, the speed of which depends only on the ratio of wavelength to wave period. Deep-water waves occur where water depth is greater than half the wavelength.

As waves approach the coast, the wave orbitals begin to touch the sea floor (also referred to as wave-base) and wave speed decreases. At these depths (depth is less than half the wavelength), loose sediment can be moved by the wave orbitals. Some energy is transferred to the sea floor, but to conserve energy, the height, or wave amplitude must also increase. As you can see in the diagram, the orbitals also become flattened. At this stage, the waves have become shallow-water waves.

Although it may seem counterintuitive, tsunamis behave as shallow-water waves. They have long wavelengths, commonly measured in 10s to 100s of kilometres. The speed of shallow-water waves, including tsunamis, is independent of their wavelength, but is dependent on water depth in the following way:

Speed = √(g . depth) (g = gravitational constant, 9.8m/s/s; depth in metres)

In the case of tsunamis, the wavelength is many times greater than water depth, even in oceans more than 4000m deep. For example, a tsunami traveling across ocean that is 4000m deep will have a speed of 198m/second, or 713 km/hour. This animation of the 2010, M8.8 Chile earthquake and tsunami gives an impression of the speed of wave propagation across oceans, and the shape of the wave fronts. Tsunami waves commonly pass unnoticed beneath ships at sea or offshore rigs. As they approach shallower water, their speed decreases to between 40-80km/hour (because speed is dependent on water depth), but the amount of energy in the wave changes very little; to compensate, the wave amplitude must increase. Earthquakes that generate tsunamis create several waves that spread out from the epicentre. All these waves can be destructive, and in some cases the first wave is the least harmful. It is also possible for a wave trough to reach the coast before the first wave crest; this results in a rapid drawdown of the water-level, exposing parts of the foreshore that would not normally be seen at even the lowest tides. Unfortunately, in all too short a time, the absence of water is replaced by a more menacing prospect.

Landslides can also produce monster waves; Lituya Bay in Alaska, 1958 is a good example with first-hand witnesses to the 15-22m wave. A prime example of volcanic eruption-derived waves is the cataclysmic 1883 Krakatoa eruption; a 30m tsunami wreaked havoc in Indonesia and across Sunda Strait.

Tsunami warning systems generally involve an international effort to, in the first instance, detect and pinpoint the epicentre of large earthquakes, and secondly, to detect tsunamis and predict their arrival times at different locations. There is a particular focus on submarine and near-coast, shallow crust seismic events of magnitude 7 and greater; high magnitude earthquakes deeper than about 100km generally do not produce destructive tsunamis. Tsunami detection buoys have installed in 59 deep ocean locations, most around the Pacific rim. The map shows the buoys to be located along tectonically active plate margins, such as the west coasts of North and South America, the Aleutian Arc, and other volcanic arcs – subduction zones from Japan through to New Zealand.

The deep-water buoys are anchored to the sea floor; for each sea-bottom buoy there is a linked surface buoy that relays data via satellite. The deep buoys measure subtle changes in water pressure that can be used to calculate changes in sea-surface height. The latest models have two-way communications so that a particular buoy can be programmed to search for pressure changes if an earthquake is known to have occurred. Of course, all this is fine if a region has several hours to prepare for possible inundation. Those close to epicentres may only have a few minutes to react.

The technology for tsunami prediction and warning is always improving. This is particularly the case for new generations of satellite that are tasked with collecting all manner of climate-related data, data relating to short- and long-term sea-level changes, and subtle changes in gravity and magnetic fields associated with earth’s ever-changing profile.

A few websites:
National Tsunami Warning Centre

Some Tsunami video clips

Boxing Day tsunami 2004 (Cornell Univ. animation)

The original post can be found here

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